(2) Under section 211(a), the Commission may issue an order requiring a transmitting utility to provide transmission services (including any enlargement of transmission capacity necessary to provide such services) only if an applicant has made a request for transmission services to the transmitting utility that would be the subject of such order at least 60 days prior to its filing of an application for such order. The requirement in section 211(a) that an applicant make such a request will be met if such an applicant has, pursuant to section 213(a) of the FPA, made a good faith request to a transmitting utility to provide wholesale transmission services and requests specific rates and charges, and other terms and conditions.

(3) It is the Commission's intention to apply the standards of this Statement of Policy when determining whether and when a valid “good faith” request for service was made.

(4) It is the Commission's intention to encourage an open exchange of information that exhibits a reasonable degree of specificity and completeness between the party requesting transmission services and the transmitting utility.

(5) The Commission intends to apply this Statement of Policy so as to carry out Congress' objective that, subject to appropriate terms and conditions and just and reasonable rates, in conformance with section 212 of the FPA, access to the electric transmission system for the purposes of wholesale transactions be more widely available.

(b) The Components of a good faith request. The Commission generally considers the following to constitute the minimum components of a good faith request for transmission services:

(1) The identity, address, telephone number, and facsimile number of the party requesting transmission services, and the same information, if different, for the party's contact person or per

sons.

(2) A statement that the party requesting transmission services is, or will be upon commencement of service, an entity eligible to request transmission under sections 211(a) and 213(a) of the FPA.

(3) A statement that the request for transmission services is intended to satisfy the "request for transmission services" requirement under sections 211(a) and 213(a) of the FPA, and that the request is not a request for mandatory retail wheeling prohibited under section 212(h) of the FPA.

(4) The party requesting transmission services should specify the character and nature of the services requested. Some types of service may require more detailed information than others. Where point-to-point service is requested, the party requesting transmission services should specify the anticipated point(s) of receipt to the transmitting utility's grid and the anticipated point(s) of delivery from the transmitting utility's grid. Where a party requesting transmission services requests additional flexibility to schedule multiple resources to meet its needs (e.g., network service), the request for services should contain a description of the requested services in sufficient detail to permit the transmitting utility to model the additional services on its transmission system.

(5) The names of any other parties likely to provide transmission service to deliver electric energy to, and receive electric energy from, the transmitting utility's grid in connection with the requested transmission services.

(6) The proposed dates for initiating and terminating the requested transmission services.

(7) The total amount of transmission capacity being requested.

(8) To the extent it is known or can be estimated, a description of the "expected transaction profile" including load factor data describing the hourly quantities of power and energy the party requesting transmission services would expect to deliver to the transmitting utility's grid at relevant points of interconnection. In the event delivery is to multiple points within the transmitting utility's electric control area, the requestor should describe, to the extent it is known or can be estimated, the expected load (over a given duration of time) at each such delivery point.

179-058 0-98--2

(9) Whether firm or non-firm service is being requested. Where a party requests non-firm service, it should specify the priority of service it is willing to accept, or the conditions under which it is willing to accept interruption or curtailment, if known.

(10) A statement as to whether the request is being made in response to a solicitation and a copy of the solicitation if publicly available. This will help the transmitting utility determine whether requests for transmission service are duplicative or mutually exclusive of requests filed by other parties.

(11) The proposed rates, terms and conditions for the requested transmission services as required by section 213(a). It is not necessary for the requestor to propose a specific numerical rate. Rather, a party requesting transmission services can fulfill the rates, terms and conditions requirement by specifying a rate methodology (e.g., embedded or incremental cost) or by referencing an existing formula rate, transmission tariff, or transmission contract. The validity of the good faith request will not depend on the rates proposed by the party requesting transmission services. This requirement is not intended to allow utilities to delay responses to requests for transmission services, or to deny requests for transmission services on the basis of an overly rigid or technical approach to the "rates, terms and conditions" element of the request.

(12) Any other information to facilitate the expeditious processing of its request. Such information will improve the negotiation process, reduce costs, and will improve chances to arrange the requested transmission without resorting to section 211 application procedures before the Commission.

(c) Components of a Reply to a Good Faith Request. The Commission generally considers the following to constitute the minimum components of a reply to a good faith request for transmission services under section 213(a):

(1) Unless the parties agree to a different time frame, the transmitting utility must acknowledge the request within 10 days of receipt. The acknowledgement must include a date by which a response will be sent to the party re

questing transmission services and a statement of any fees associated with responding to the request (e.g., initial studies).

(2) The transmitting utility may ask the applicant to provide clarification of only the information needed to evaluate and process a "good faith" request. If the person requesting transmission services believes the transmitting utility is attempting to frustrate the process by making excessive requests for clarification, it may raise this issue if, and when, it files a request for a section 211 order with the Commission.

(3) The transmitting utility must respond to a request within 60 days of receipt or some other mutually agreed upon response date. If both parties agree to an alternative schedule, the agreement must be in writing and signed by both parties.

(4) If the transmitting utility determines that it can provide all the requested services from existing capacity, it should respond by offering the party requesting transmission services an executable service agreement that at a minimum contains the following information:

(i) A description of the proposed transmission rate and any other costs. It is not necessary for the proposed service agreement to contain a fully developed cost-of-service. However, the agreement should explain the basis for the charges for each component of service, including the unbundled components of any transmission rate as well as any other charges.

(ii) The proposed service agreement should explicitly describe all of the applicable terms and conditions of the transmission services provided under the agreement.

(iii) The transmitting utility should accompany the proposed service agreement with a clear statement of the time during which the offer to provide the transmission services will remain open. An open agreement offer may obligate the seller while imposing no countervailing obligation on the purchaser, and an unexecuted contract potentially ties up transmission facilities, thus jeopardizing the availability and price for subsequent requests that would use the same facilities. However,

at a minimum, a transmitting utility should permit the party requesting transmission services sufficient time to review service agreements and coordinate multiple stages of joint transactions.

(5) If the transmitting utility determines that it must construct additional facilities or modify existing facilities to provide all or part of the requested services, it must:

(1) Identify the specific constraints and their duration that prevent it from providing all the requested services and explain how these constraints prevent it from providing all the requested services or the desired level of firmness.

(ii) Provide to the applicant all studies, computer input and output data, planning, operating and other documents, work papers, assumptions and any other material that forms the basis for determining the constraints.

(iii) Offer to the applicant an executable agreement under which the applicant agrees to reimburse the transmitting utility for all costs of performing any studies necessary to determine what changes to the transmitting utility's grid are needed to overcome the constraint and provide the requested services, their cost, and the estimated time to complete them. At a minimum, the proposed agreement should contain the following:

(A) An estimate of the cost of the study and the time required to complete it, and

(B) A commitment to supply to the party requesting transmission services all computer input and output data, planning, operating and other documents, work papers, assumptions and any other material used to perform the study.

(iv) If a transmitting utility determines that it can provide part but not all of the requested services without building new facilities, it should inform the applicant of any portion of the requested services that can be performed without constructing additional facilities or modifying existing facilities. In effect, the transmitting utility may be able to treat such a request as two separate transactionsone for service on existing facilities and the other as a request involving ex

pansion decisions. Furthermore, where there are alternative, less expensive means of satisfying all or a portion of a transmission request, the Commission expects the transmitting utility to explore such alternatives (e.g., (e.g., redispatching certain generating units to alleviate a constraint).

[58 FR 38969, July 21, 1993]

§ 2.21 Regional Transmission Groups. (a) General policy. The Commission encourages Regional Transmission Groups (RTGs) as a means of enabling the market for electric power to operate in a more competitive and efficient way. The Commission believes that RTGS can provide a means of coordinating regional planning of the transmission system and assuring that system capabilities are always adequate to meet system demands. RTG agreements that contain components that satisfy paragraphs (b) and (c) of this section generally will be considered to be just, reasonable, and not unduly discriminatory or preferential under the Federal Power Act (FPA). The Commission encourages RTG agreements that contain as much detail as possible in all of the components listed, particularly if the RTG participants will be seeking Commission deference to decisions reached under an RTG agreement.

(b) Organizational components. (1) An RTG agreement should provide for broad membership and, at a minimum, allow any entity that is subject to, or eligible to apply for, an order under section 211 of the FPA to be a member. An RTG agreement should encompass an area of sufficient size and contiguity to enable members to provide transmission services in a reliable, efficient, and competitive manner.

(2) An RTG agreement should provide a means of adequate consultation and coordination with relevant state regulatory, siting, and other authorities.

(3) An RTG agreement should include fair and nondiscriminatory governance and decisionmaking procedures, including voting procedures.

(c) Other components. (1) An RTG agreement should impose on member transmitting utilities an obligation to provide transmission services for other members, including the obligation to

enlarge facilities, on a basis that is consistent with sections 205, 206, 211, 212 and 213 of the FPA. To the extent practicable and known, the RTG agreement should specify the terms and conditions under which transmission services will be offered.

(2) An RTG agreement should require, at a minimum, the development of a coordinated transmission plan on a regional basis and the sharing of transmission planning information, with the goal of efficient use, expansion, and coordination of the interconnected electric system on a grid-wide basis. An RTG agreement should provide mechanisms to incorporate the transmission needs of non-members into regional plans. An RTG agreement should include as much detail as possible with regard to operational and planning procedures.

(3) An RTG agreement should include voluntary dispute resolution procedures that provide a fair alternative to resorting in the first instance to section 206 complaints or section 211 proceedings.

(4) An RTG agreement should include an exit provision for RTG members that leave the RTG, specifying the obligations of a departing member.

(d) Filing procedures. Any proposed RTG agreement that in any manner affects or relates to the transmission of electric energy in interstate commerce by a public utility, or rates or charges for such transmission, must be filed with the Commission. Any public utility member of a proposed RTG may file the RTG agreement with the Commission on behalf of the other public utility members under section 205 of the FPA.

[58 FR 41632, Aug. 5, 1993]

§ 2.22 Pricing policy for transmission services provided under the Federal Power Act.

(a) The Commission has adopted a Policy Statement on its pricing policy for transmission services provided under the Federal Power Act. That Policy Statement can be found at 69 FERC 61,086. The Policy Statement constitutes a complete description of the Commission's guidelines for assessing the pricing proposals. Paragraph

(b) of this section is only a brief summary of the Policy Statement.

(b) The Commission endorses transmission pricing flexibility, consistent with the principles and procedures set forth in the Policy Statement. It will entertain transmission pricing proposals that do not conform to the traditional revenue requirement as well as proposals that conform to the traditional revenue requirement. The Commission will evaluate "conforming" transmission pricing proposals using the following five principles, described more fully in the Policy Statement.

(1) Transmission pricing must meet the traditional revenue requirement. (2) Transmission pricing must reflect comparability.

(3) Transmission pricing should promote economic efficiency.

(4) Transmission pricing should promote fairness.

(5) Transmission pricing should be practical.

(c) Under these principles, the Commission will also evaluate "non-conforming" proposals which do not meet the traditional revenue requirement, and will require such proposals to conform to the comparability principle. Non-conforming proposals must include an open access comparability tariff and will not be allowed to go into effect prior to review and approval by the Commission under procedures described in the Policy Statement.

[59 FR 55039, Nov. 3, 1994]

§2.23 Use of reserved authority in hydropower licenses to ameliorate cumulative impacts.

The Commission will address and consider cumulative impact issues at original licensing and relicensing to the fullest extent possible consistent with the Commission's statutory responsibility to avoid undue delay in the relicensing process and to avoid undue delay in the amelioration of individual project impacts at relicensing. To the extent, if any, that it is not possible to explore and address all cumulative impacts at relicensing, the Commission will reserve authority to examine and address such impacts after the new license has been issued, but will define that reserved authority as narrowly and with as much specificity as

possible, particularly with respect to the purpose of reserving that authority. The Commission intends that such articles will describe, to the maximum extent possible, reasonably foreseeable future resource concerns that may warrant modifications of the licensed project. Before taking any action pursuant to such reserved authority, the Commission will publish notice of its proposed action and will provide an opportunity for hearing by the licensee and all interested parties. Hydropower licenses also contain standard "reopener" articles (see §2.9 of this part) which reserve authority to the Commission to require, among other things, licensees of projects located in the same river basin to mitigate the cumulative impacts of those projects on the river basin. In light of the policy described above, the Commission will use the standard "reopener" articles to explore and address cumulative impacts only (except in extraordinary circumstances) where such impacts were not known at the time of licensing or are the result of changed circumstances. The Commission has authority under the Federal Power Act to require licensees, during the term of the license, to develop and provide data to the Commission on the cumulative impacts of licensed projects located in the same river basin. In issuing both new and original licenses, the Commission will coordinate the expiration dates of the licenses to the maximum extent possible, to maximize future consideration of cumulative impacts at the same time in contemporaneous proceedings at relicensing. The Commission's intention is to consider to the extent practicable cumulative impacts at the time of licensing and relicensing, and to eliminate the need to resort to the use of reserved authority.

[59 FR 66718, Dec. 28, 1994]

§ 2.24 Project decommissioning at relicensing.

The Commission issued a statement of policy on project decommissioning at relicensing in Docket No. RM93–23000 on December 14, 1994.

[60 FR 347, Jan. 4, 1995]

§2.25 Ratemaking treatment of the cost of emissions allowances in coordination transactions.

(a) General Policy. This Statement of Policy is adopted in furtherance of the goals of Title IV of the Clean Air Act Amendments of 1990, Pub. L. 101-549, Title IV, 104 Stat. 2399, 2584 (1990).

(b) Costing Emissions Allowances in Coordination Sales. If a public utility's coordination rate on file with the Commission provides for recovery of variable costs on an incremental basis, the Commission will allow recovery of the incremental costs of emissions allowances associated with a coordination sale. If a coordination rate does not reflect incremental costs, the public utility should propose alternative allowance costing methods or demonstrate that the coordination rate does not produce unreasonable results. The Commission finds that the cost to replace an allowance is an appropriate basis to establish the incremental cost.

(c) Use of Indices. The Commission will allow public utilities to determine emissions allowance costs on the basis of an index or combination of indices of the current price of emissions allowances, provided that the public utility affords purchasing utilities the option of providing emissions allowances. Public utilities should explain and justify any use of different incremental cost indices for pricing coordination sales and making dispatch decisions.

(d) Calculation of Amount of Emissions Allowances Associated With Coordination Transactions. Public utilities should explain the methods used to compute the amount of emissions allowances included in coordination transactions.

(e) Timing. (1) Public utilities should provide information to purchasing utilities regarding the timing of opportunities for purchasers to stipulate whether they will purchase or return emissions allowances. A public utility may require a purchasing utility to declare, no later than the beginning of the coordination transaction:

(1) Whether it will purchase or return emissions allowances; and

(ii) If it will return emissions allowances, the date on which those allowances will be returned.

(2) Public utilities may include in agreements with purchasing utilities